1. Field of the Invention
This invention relates to a system for cooling process fluids, where localized or bulk overheating of the cooling fluid is undesirable. It is particularly applicable to the steam generator blowdown fluid in a nuclear plant.
2. Description of the Prior Art
In nuclear reactor plants incorporating a steam generator which serves to transfer heat from the reactor primary system to the secondary steam system, a method for purification of the steam system water is typically employed. This method may include purification of at least a portion of the feedwater stream prior to entry into the steam generator. Also typically incorporated is a blowdown system which serves to remote any undesirable chemical buildup of impurities within the steam generator. Such blowdown systems may operate either continuously or intermittently and typically remove water from the lower portion of the steam cycle side of the steam generator. The lower portion of the steam cycle side of the steam generator are the most likely locations for solid precipitation buildup.
As the blowdown fluid removed is at a significantly high temperature and pressure condition, it must be cooled before such means as ion exchange demineralization may be utilized for purification of the blowdown fluid. Initial nuclear plant designs utilized a system whereby the high temperature, high pressure, blowdown fluid was directed to a flash tank. These systems thereby avoided the use of any heat exchangers to cool the blowdown fluid or did provide a heat exchanger primarily to preheat boiler feedwater while cooling the blowdown water. With the boiler feedwater at high pressures and with carefully controlled water chemistry, corrosive conditions typical of ordinary service water cooling were avoided. The flash tank type system has the drawback that approximately one-third of the blowdown fluid flashes to steam, and is discharged. Not only does this require makeup of that amount of water, but also any entrained volatile gases, such as iodine, are released to the atmosphere. With increased regulatory requirements as to redundant means of protection against radioactive releases, and with regard to chemical and thermal discharges, the flash tank type systems no longer prove adequate.
Newer systems therefore were designed which basically comprise feeding the blowdown fluid through a single heat exchanger, and removing heat from the blowdown fluid by the plant cooling water (service water or component cooling water). However, design and operating considerations arise with the single heat exchanger designs of the type presently used. The blowdown fluid is at very high pressure and temperature conditions relative to the plant service water. The blowdown fluid typically is at a pressure of between 800 to 1200 psia, depending upon steam generator operating conditions, and at saturated temperature at the given operating pressure. On the other hand, the plant service water, at least for design purposes, is at a temperature in the range of 95.degree. F, and at a pressure in the range of 40 psig. As is evident, these conditions may cause significant operating restrictions on a single heat exchanger.
For example, the typical allowable temperature rise for cooling water is approximately 20.degree. F. This compares with a required temperature drop in the blowdown fluid on the order of 400.degree. F. Roughly, the result is that the cooling flow rate must be approximately 20 times the blowdown fluid flow rate. Severe restrictions are therefore placed on the heat exchanger surface arrangement in order to provide optimum velocities, heat transfer coefficients, and heat transfer surface temperatures, among others. Also, as the inlet service cooling water temperature will be approximately 95.degree. compared to an inlet blowdown fluid temperature between 500.degree. and 600.degree. F, coupled with the large unbalanced mass flow rate, an extensive and costly engineering analysis to evaluate the effect of thermal transients on heat exchanger design and mechanical integrity is required. Further, the temperature relationships result in a condition at the hot end of the heat exchanger in which the bulk water temperature on the blowdown side is on the order of 550.degree. F and on the cooling water side about 120.degree. F. This condition can result in a heat transfer surface temperature high enough on the cooling water side to cause localized boiling. If boiling occurs, there likely will be concentration and precipitation of undesirable chemical solids on the heat transfer surface, a condition which fosters rapid corrosion and tube failure. Under such conditions it would not be unlikely to expect only a few months operation of the heat exchanger before significant failures would occur. The most obvious solution to the boiling problem would be to raise the cooling water pressure to prevent boiling. However, in order to insure that boiling would not occur, a relatively high pressure, on the order of 150 psig, would be required. Such pressures are not normally available from the cooling water pumps, which must operate on a very large volumetric fluid flow rate. Although a booster pump for the cooling water could be incorporated specifically to increase the pressure, such pumps would increase plant costs, and would necessitate detailed system analysis for each plant design. The affects associated with the flow rates, pressure conditions, and temperature differentials are also concerns in other nuclear and non-nuclear systems for cooling process fluids.
The ideal solution to these concerns would be a system utilizing static components and existing cooling water system apparatus.